Method for completing tight oil and gas reservoirs

ABSTRACT

A method and apparatus for processing a subterranean formation comprising stimulating and fracturing a subterranean formation, and drilling the subterranean formation wherein the drilling and fracturing occurs without removing equipment for drilling from the formation. A method and apparatus for drilling and fracturing a subterranean formation, comprising a drill string assembly and a hydraulic fracturing system, wherein the drill string and fracturing system are in communication with a wellbore and wherein the drill string and a fracture formed by the hydraulic fracturing system are less than about 1000 feet apart. A method and apparatus for processing a subterranean formation comprising fracturing a subterranean formation using a hydraulic fracturing system and drilling the subterranean formation using a drill string assembly wherein the drilling and fracturing occurs without removing the drill string from the formation, and wherein the fracturing occurs via ports in the drill string assembly.

PRIORITY

This application claims priority as a non provisional application ofU.S. Provisional Patent Application No. 61/211,194, filed Mar. 27, 2009,which is hereby incorporated by reference in its entirety.

BACKGROUND

Many geological formations require hydraulic stimulation to producehydrocarbons. Examples of formations that require hydraulic stimulationwould be tight gas sands such as the Cotton Valley of East Texas, theBarnett Shale in Arkansas, and the Niobrara Sand in Colorado. Suchformations are usually hydraulically fractured after the drillingprocess. The typical procedure would be to drill, then case and cementthe well, and then perforate the desired intervals and hydraulicallyfracture them by injecting fluid into the perforated interval at highpressure.

Completing tight gas and oil wells using hydraulic fracturing andhorizontal/deviated wellbores recovers the most reserves in a shorterperiod of time with less cost than conventional procedures andtechniques. Conventional completions normally have a wellbore that isdrilled, the drilling assembly is then removed from the wellbore, andthe completion assembly is run in the wellbore. After this, thecompletion or stimulation takes places at each zone of interest. Thisprocess is very costly and time consuming. Also, in fracturingoperations, proppant is placed in the fracture in order to keep thefracture open after pumping is stopped. Efforts in the past have beenmade to ease the fracturing operations such as modifying fluid orproppant properties to optimize proppant placement. In any event, asystem for increasing the production of a subterranean formation withreduced process steps is needed.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a sectional view of an embodiment of a drill string assemblyand subterranean formation.

FIG. 2 is a schematic view of an embodiment of surface equipment andwellbore configured for hydraulic fracturing.

FIG. 3 is a sectional view of a an embodiment of a drill string assemblyand a fracture in the subterranean formation.

FIG. 4 is a dimensional view of an embodiment of a wellbore positionedthrough several fractures in the subterranean formation.

FIG. 5 is a dimensional view of an embodiment of wellbores positionedthrough several fractures in the subterranean formation.

FIG. 6 is a dimensional view of an alternative embodiment of wellboresin a subterranean formation.

FIG. 7 is a plot of pressure versus time during an embodiment of ahydraulic fracturing operation.

FIG. 8 is a dimensional view of an embodiment of a wellbore and drillingassembly positioned to fracture the subterranean formation.

FIG. 9 is a dimensional view of an alternative embodiment of a wellboreand drilling assembly positioned to fracture the subterranean formation.

FIG. 10 is a schematic diagram of an embodiment of a tangentialwell-bore stress.

SUMMARY

Embodiments of the invention relate to a method and apparatus forprocessing a subterranean formation comprising stimulating andfracturing a subterranean formation and drilling the subterraneanformation, wherein the drilling and fracturing occurs without removingdownhole drilling equipment from the formation. In some embodiments, thedrilling and fracturing form a conductive fracture using acid. Someembodiments may benefit from forming a seal along a surface of theformation. In some embodiments, the seal is temporary and/or the seal isplaced during drilling. In some embodiments, the drilling accurs using afluid selected for its density, lubricity, frictional properties, sonictravel properties, carry proppant, formation damage and its ability tomodify fluid temperature.

Some embodiments may benefit from introducing a composition along thesurface of the subterranean formation. In some embodiments, thecomposition stabilizes the surface of the subterranean formation. Insome embodiments, the composition has a stability that is tailored todegrade over time. In some embodiments, the composition comprises carbondioxide or nitrogen. In some embodiments, the composition iselectrosensitive or magneto sensitive. In some embodiments, thecomposition comprises a material that melts below formation temperature.In some embodiments, the composition comprises crosslinked polymers.

In some embodiments, the fracturing comprises proppant. In someembodiments, the proppant comprises material to make it swell, shrink,or form acid. In some embodiments, the proppant comprises proppant withmultiple diameters.

In some embodiments, a filter cake is formed along a surface of thesubterranean formation. In some embodiments, the filter cake comprises abreaker material. In some embodiments, the material is encapsulated. Insome embodiments, the filter cake comprises a material to decrease cakepermeability. In some embodiments, the material comprises latex or anemulsion. In some embodiments, the filter cake is tailored to prevent orallow fracture. In some embodiments, the filter cake is self-diverting.

In some embodiments, the equipment comprises a drill string. Someembodiments may benefit from controlling and/or blocking the fluidreturn system. In some embodiments, a pressure on the outer surface of adrill bit is controlled. Some embodiments may benefit from pumping fluidthrough a bypass, annulus, or a drill string. Some embodiments maybenefit from collecting cuttings via a drillstring or annulus. Someembodiments may benefit from introducing a packer into the wellbore.Some embodiments may benefit from triggering the fracturing by droppinga ball into the drillstring. Some embodiments may benefit from usingelectrical line or optical fibers to provide feedback to control thefracturing.

In some embodiments, the drilling occurs horizontally, vertically,and/or with multiple branches. Some embodiments may benefit frommeasuring microseismic, temperature, and/or sonic information andcontrolling the fracturing and/or drilling using the information. Someembodiments may benefit from introducing afoam or an energized fluidinto the wellbore.

In some embodiments, the fracturing occurs as the drill string assemblyis traveling away from a wellhead. In some embodiments, the fracturingoccurs as the drill string assembly is traveling toward a wellhead.

Embodiments of the invention relate to a method and apparatus fordrilling and fracturing a subterranean formation comprising a drillstring assembly and a hydraulic fracturing system, wherein the drillstring and fracturing system are in communication with a wellbore andwherein the drill string and a fracture formed by the hydraulicfracturing system are less than about 1000 feet apart. Some embodimentsmay benefit from a packer. In some embodiments, drill string isconfigured to withstand exposure to hydraulic fracturing. In someembodiments, the hydraulic fracturing system is configured to fractureone stage at a time. Some embodiments may benefit from a seal thatencompasses a wellbore, drill string assembly, and a hydraulicfracturing fluid inlet port. In some embodiments, the drill stringassembly is configured to deliver hydraulic fracturing fluid.

Embodiments of the invention relate to a method and apparatus forprocessing a subterranean formation comprising fracturing a subterraneanformation using a hydraulic fracturing system and drilling thesubterranean formation using a drill string assembly, wherein thedrilling and fracturing occurs without removing the drill string fromthe formation, and wherein the fracturing occurs via ports in the drillstring.

DETAILED DESCRIPTION

A method for fracturing while drilling is desirable for increasedefficiency and reduced costs. Creating subterranean fractures withoutremoving the drilling equipment from a wellbore eliminates individualprocess steps such as drilling, casing, completing, and perforating.This technique enables fracturing operations and uses less hardware forcompletion in the wellbores. Throughout this application, reference ismade to fracturing a formation. In this application, unless indicatedotherwise, fracturing may encompass stimulating a formation or providinga matrix treatment to the formation as well as fracturing a formation.

Mechanical Equipment

Drilling

Any drilling equipment could be used for the drilling aspect ofembodiments of this invention. The equipment may be selected for itsresilient properties over a high pressure regime and upon exposure to avariety of chemical processes, mechanical stress created by drilling,fracturing, and proppant placement, and/or high temperatures. At aminimum, the drilling equipment should include a drillbit. Further, thedrilling equipment may include protective shields and/or electricalcomponents designed to withstand harsh conditions. For example, someembodiments may benefit from the couplers described in U.S. Pat. Nos.6,866,306 and 6,641,434, which are hereby incorporated by reference.Also, the drilling equipment may contain nozzles or other fluid deliverymechanisms to deliver drilling fluid and/fracturing fluid and/or otherfluids.

FIG. 1 includes a downhole drilling assembly that includes downholedrilling equipment and illustrates a wellsite system in whichembodiments of the present invention may be employed. The wellsite canbe onshore or offshore. In this exemplary system, a borehole 11 isformed in subsurface formations by rotary drilling in a manner that iswell known. Embodiments of the invention can also use directionaldrilling, as will be described hereinafter.

A drill string 12 is suspended within the borehole 11 and has abottomhole assembly 100 which includes a drill bit 105 at its lower end.The surface system includes platform and derrick assembly 10 positionedover the borehole 11, the assembly 10 including a rotary table 16, kelly17, hook 18 and rotary swivel 19. The drill string 12 is rotated by therotary table 16, energized by means not shown, which engages the kelly17 at the upper end of the drill string. The drill string 12 issuspended from a hook 18, attached to a traveling block (also notshown), through the kelly 17 and a rotary swivel 19 which permitsrotation of the drill string relative to the hook. A top drive systemcould alternatively be used.

In the example of some embodiments, the surface system further includesdrilling fluid or mud 26 stored in a pit 27 formed at the well site. Apump 29 delivers the drilling fluid 26 to the interior of the drillstring 12 via a port in the swivel 19, causing the drilling fluid toflow downwardly through the drill string 12 as indicated by thedirectional arrow 8. The drilling fluid exits the drill string 12 viaports in the drill bit 105, and then circulates upwardly through theannulus region between the outside of the drill string and the wall ofthe borehole, as indicated by the directional arrows 9. In this manner,the drilling fluid lubricates the drill bit 105 and carries formationcuttings up to the surface as it is returned to the pit 27 forrecirculation. The drilling fluid may also be cooled by injectingcooling liquids, fluids, or gases near the pump 29 or the port in theswivel 19.

The bottom hole assembly 100 of the illustrated embodiment alogging-while-drilling (LWD) module 120, a measuring-while-drilling(MWD) module 130, a roto-steerable system and motor, and drill bit 105.

The LWD module 120 is housed in a special type of drill collar and cancontain one or a plurality of logging tools. More than one LWD and/orMWD module can be employed, e.g. as represented at 120A (Referencesthroughout to a module at the position of 120 can alternatively mean amodule at the position of 120A as well.). The LWD module includesmeasuring, processing, and storing information capabilities, as well asthe ability to communicate with the surface equipment. In someembodiments, the LWD module includes a pressure measuring device.

The MWD module 130 is also housed in a special type of drill collar andcan contain one or more devices for measuring characteristics of thedrill string and drill bit. The MWD tool further includes an apparatus(not shown) for generating electrical power to the downhole system. Thismay typically include a mud turbine generator powered by the flow of thedrilling fluid, it being understood that other power and/or batterysystems may be employed. In some embodiments, the MWD module includesone or more of the following types of measuring devices: a weight-on-bitmeasuring device, a torque measuring device, a vibration measuringdevice, a shock measuring device, a stick slip measuring device, adirection measuring device, and an inclination measuring device.

The placement of wires in drill pipes for carrying signals has beenstudied. Some early approaches to a wired drill string are disclosed inU.S. Pat. Nos. 4,126,848, 3,957,118, and 3,807,502 and in thepublication “Four Different Systems Used for MWD,” W. J. McDonald, TheOil and Gas Journal, pages 115-124, Apr. 3, 1978.

Using inductive couplers located at the pipe joints has also beenstudied. The following disclose use of inductive couplers in a drillstring: U.S. Pat. No. 4,605,268; Russian Federation published patentapplication 2140527, filed Dec. 18, 1997; Russian Federation publishedpatent application 2040691, filed Feb. 14, 1992; and WO Publication90/14497A2. Also, see U.S. Pat. Nos. 5,052,941, 4,806,928, 4,901,069,5,531,592, 5,278,550; and 5,971,072.

U.S. Pat. Nos. 6,641,434 and 6,866,306, are both hereby incorporated byreference and describe a wired drill pipe joint that is for reliablytransmitting measurement data in high-data rates, bidirectionally,between a surface station and locations in the borehole. The '434 and'306 patents disclose a low-loss wired pipe joint in which conductivelayers reduce signal energy losses over the length of the drill stringby reducing resistive losses and flux losses at each inductive coupler.The wired pipe joint is robust in that the wired pipe joint remainsoperational in the presence of gaps in the conductive layer.

A particularly advantage is controlled steering or “directionaldrilling.” In this embodiment, a roto-steerable subsystem 150 isprovided. Directional drilling is the intentional deviation of thewellbore from the path it would naturally take. In other words,directional drilling is the steering of the drill string so that ittravels in a desired direction. Directional drilling is advantageous inoffshore drilling because it enables many wells to be drilled from asingle platform. Directional drilling also enables horizontal drillingthrough a reservoir. Horizontal drilling enables a longer length of thewellbore to traverse the reservoir, which increases the production ratefrom the well. A directional drilling system may also be used invertical drilling operation as well. Often the drill bit will veer offof a planned drilling trajectory because of the unpredictable nature ofthe formations being penetrated or the varying forces that the drill bitexperiences. When such a deviation occurs, a directional drilling systemmay be used to put the drill bit back on course.

Directional drilling includes the use of a rotary steerable system(“RSS”). The RSS includes rotating the drill string from the surface anddownhole devices cause the drill bit to drill in the desired direction.Rotating the drill string greatly reduces the likelihood of the drillstring getting hung up or stuck during drilling. Rotary steerabledrilling systems for drilling deviated boreholes into the earth may begenerally classified as either “point-the-bit” systems or “push-the-bit”systems.

In the point-the-bit system, the axis of rotation of the drill bit isdeviated from the local axis of the bottom hole assembly in the generaldirection of the new hole. The hole is propagated in accordance with athree point geometry defined by upper and lower stabilizer touch pointsand the drill bit. The angle of deviation of the drill bit axis coupledwith a finite distance between the drill bit and lower stabilizerresults in the non-collinear condition required for a curve to begenerated. There are many ways in which this may be achieved including afixed bend at a point in the bottom hole assembly close to the lowerstabilizer or a flexure of the drill bit drive shaft distributed betweenthe upper and lower stabilizer. In its idealized form, the drill bit isnot required to cut sideways because the bit axis is continually rotatedin the direction of the curved hole. Examples of point-the-bit typerotary steerable systems, and how they operate are described in UnitedStates Patent Application Publication Number 2001/0052428 and U.S. Pat.Nos. 6,401,842, 6,394,193; 6,364,034; 6,244,361; 6,158,529; 6,092,610;and 5,113,953, which are all hereby incorporated by reference.

In the push-the-bit rotary steerable system there is usually nospecially identified mechanism to deviate the bit axis from the localbottom hole assembly axis. Instead, the requisite non-collinearcondition is achieved by causing either or both of the upper or lowerstabilizers to apply an eccentric force or displacement in a directionthat is preferentially orientated with respect to the direction of holepropagation. Again, there are many ways in which this may be achieved,including non-rotating (with respect to the hole) eccentric stabilizers(displacement based approaches) and eccentric actuators that apply forceto the drill bit in the desired steering direction. Steering is achievedby creating non co-linearity between the drill bit and at least twoother touch points. In its idealized form the drill bit is required tocut sideways in order to generate a curved hole. Examples ofpush-the-bit type rotary steerable systems and how they operate aredescribed in U.S. Pat. Nos. 5,265,682; 5,553,678; 5,803,185; 6,089,332;5,695,015; 5,685,379; 5,706,905; 5,553,679; 5,673,763; 5,520,255;5,603,385; 5,582,259; 5,778,992; 5,971,085 all herein incorporated byreference.

In some embodiments, the drilling motor may be top drive (from a rotarytable). In some embodiments, the motor may be driven at the bit andfeature some modification such as using a static screen isolating toolsfrom the wear and tear of hydraulic fracturing. In some embodiments, thedrill string may be partially rotating. In some embodiments, the drillcomponents may need to be specially configured to resist being lodgedinto the wellbore during drilling or fracturing, which may be especiallyimportant during directional drilling.

Coiled Tubing

Coiled tubing has long been used in well operations in order to placedesirable fluids such as acids, cement and the like in a well utilizinga relatively simple apparatus comprising a long length of tubing, oftenas long as 25,000 feet, wound onto a large spool or reel. In coiledtubing operations, tubing from the reel is fed into the wellboreutilizing an injector mechanism which is well known in the art. Fluidscan be fed through a fitting on the tubing reel, through the tubing to atool disposed on the inserted end of the coiled tubing within the well.In some embodiments, coiled tubing with drilling capabilities may beused in addition to or in place of drilling equipment.

Fracturing

Fracturing a subterranean formation with a drilling string in thewellbore requires equipment that has been tailored for use with awellbore that may not include casing or completion. For example, somesurface equipment at the well head or wellbore casing or cement may notbe present. A choke line, bleedoff, and/or pressure seal may beconfigured to protect the drill string. High pressure pumps, blendingequipment, proppant storage and delivery, and other components of thesystem may need to be streamlined or aligned to provide individualstages of treatment instead of multiple stages. That is, less pumps orother equipment may be needed for some embodiments of the invention.FIG. 2 provides a schematic diagram of how the equipment may bearranged. Especially, FIG. 2 illustrates that the number of pumps andother surface equipment may be reduced to provide one stage at a timefracturing treatments instead of multiple stages at one time.

Fracture tanks 201, transfer tanks 202, proppant feeders 203, proppantconveyer 204, hopper 205, liquid transport trailer 206, fluid blendingunit 207, proppant blender 208, job monitoring unit 209, pumpers 210,manifold trailer 211, nitrogen pumpers 212, carbon dioxide transports213, booster 214, and pumper 215, densitometer 216, flowmeter 217,pressure transducer 218, and pumper 219 may all be configured to providefracturing while drilling to the well 220. At the well 220, the wellhead(not pictured) may be configured to administer drill equipment andfracturing equipment simultaneously.

Packers

In some embodiments, packers may be used to isolate sections of thewellbore. The packer may be mechanical, inflatable, or swellable. Toprovide a seal, the packer may mechanically squeeze, expand uponexposure to a fluid pressure, and/or contain a material that swells uponexposure to a fluid or other conditions. The packers may be mechanicalor chemical or both. They may have a means of activation and/or releasethat is mechanical or chemical or both. In some embodiments, the packersmay be temporary packers. In alternative embodiments, the packers mayremain in place until mechanically removed. In some embodiments, thepackers may be deployed to isolate regions of the wellbore or wellheadfrom flow backup from a hydraulic fracturing operation or from adrilling operation. In some embodiments, the packers may have mechanismsto keep from getting stuck in undesired regions of the wellbore.

Ball.

In some embodiments, a ball may be introduced into the wellbore totrigger drilling or fracturing. Aspects of the use of a ball aredescribed in more detail below.

Chemistry

Embodiments of the invention may relate to several chemical processesthat enhance the effectiveness of fracturing or drilling or both.Drilling fluid, fracturing fluid, pills, filter cake, proppant, tracers,annular protection fluid, and cooling systems may be employed tofacilitate embodiments of the invention. In some embodiments, acidfracturing may be employed, such as the fracturing described in U.S.Pat. No. 7,644,761, 7,306,041 and 6,828,280, which are all threeincorporated by reference herein in their entirety.

Drilling fluid may comprise components to significantly increasing themud weight or otherwise controlling the drilling fluid density. Asdrilling proceeds (especially for a horizontal well), some embodimentsmay create zones of various permeability along the newly generated wellfaces by weighing the drilling mud with additives. The concentration ofadditives (from 0 to a certain percentage by weight of the drilling mud)would form a filter cake of increasing permeability. The drilling fluidis cooled by injecting liquid CO₂, nitrogen, or other liquid gas at thesurface to cool the drilling fluid sufficiently to create thermallyinduced fractures in the desired geological formations near the drillbit.

Adding a material to the drilling fluid that melts at some temperatureabove ambient and below formation temperatures would significantlyincrease the impact on the formation by allowing the drilling fluid tocarry significantly more energy. When the drilling fluid with thesematerials reaches the formation area the materials would melt, absorbingsignificant energy and cooling the formation more than would be possiblewith fluids alone. Further, these materials could be chosen such thatthe liquids generated by melting the materials would provide otheruseful chemical activity downhole (such as producing liquid acid,gelling, breaking, crystallization of something in the fluid, or otherprocesses).

The hydraulic fractures may be created using water, acid, oil,hydrocarbon gas, carbon dioxide, nitrogen gas, and any combination ofthese. The carrier fluid can generally be any liquid carrier suitablefor use in oil and gas producing wells. One such liquid carrier iswater. The liquid carrier can comprise water, can consist essentially ofwater, or can consist of water. Water will typically be a majorcomponent by weight of the fluid. The water can be potable ornon-potable water. The water can be brackish or contain other materialstypical of sources of water found in or near oil fields.

A salt may be present in the fluid carrier. The salt can be presentnaturally if brine is used, or can be added to the fluid carrier. Forexample, it is possible to add to water; any salt, such as an alkalimetal or alkali earth metal salt (NaCO₃, NaCl, KCl, etc.). The salt isgenerally present in weight percent concentration between about 0.1% toabout 5%, from about 1% to about 3% by weight. One useful concentrationis about 2% by weight. Salt maybe used in higher concentrations to makea more dense fluid and thus enabling higher pressures at the fracturingpoint and lower pressures at the surface. This makes for less hydraulichorsepower and expensive pressure control equipment.

The crosslinked polymer can generally be any crosslinked polymers. Thepolymer viscosifier can be a metal-crosslinked polymer. Suitablepolymers for making the metal-crosslinked polymer viscosifiers include,for example, polysaccharides such as substituted galactomannans, such asguar gums, high-molecular weight polysaccharides composed of mannose andgalactose sugars, or guar derivatives such as hydroxypropyl guar (HPG),carboxymethylhydroxypropyl guar (CMHPG) and carboxymethyl guar (CMG),hydrophobically modified guars, guar-containing compounds, and syntheticpolymers. Crosslinking agents based on boron, titanium, zirconium oraluminum complexes are typically used to increase the effectivemolecular weight of the polymer and make them better suited for use inhigh-temperature wells.

Other suitable classes of polymers effective as viscosifiers includepolyvinyl polymers, polymethacrylamides, cellulose ethers,lignosulfonates, and ammonium, alkali metal, and alkaline earth saltsthereof. More specific examples of other typical water soluble polymersare acrylic acid-acrylamide copolymers, acrylic acid-methacrylamidecopolymers, polyacrylamides, partially hydrolyzed polyacrylamides,partially hydrolyzed polymethacrylamides, polyvinyl alcohol,polyalkyleneoxides, other galactomannans, heteropolysaccharides obtainedby the fermentation of starch-derived sugar and ammonium and alkalimetal salts thereof.

Cellulose derivatives are used to a smaller extent, such ashydroxyethylcellulose (HEC) or hydroxypropylcellulose (HPC),carboxymethylhydroxyethylcellulose (CMHEC) and carboxymethycellulose(CMC), with or without crosslinkers. Xanthan, diutan, and scleroglucan,three biopolymers, have been shown to have excellent proppant-suspensionability even though they are more expensive than guar derivatives andtherefore have been used less frequently, unless they can be used atlower concentrations.

In other embodiments, the crosslinked polymer is made from acrosslinkable, hydratable polymer and a delayed crosslinking agent,wherein the crosslinking agent comprises a complex comprising a metaland a first ligand selected from the group consisting of amino acids,phosphono acids, and salts or derivatives thereof. Also the crosslinkedpolymer can be made from a polymer comprising pendant ionic moieties, asurfactant comprising oppositely charged moieties, a clay stabilizer, aborate source, and a metal crosslinker. Said embodiments are describedin U.S. Patent Publications US2008-0280790 and US2008-0280788respectively, each of which are incorporated herein by reference.

Linear (not cross-linked) polymer systems may be used. However, in somecases, may not achieve the full benefits because they may require moreconcentration. Any suitable crosslinked polymer system may be used,including for example, those which are delayed, optimized for hightemperature, optimized for use with sea water, buffered at various pH's,and optimized for low temperature. Any crosslinker may be used, forexample boron, titanium, zirconium, aluminum and the like. Suitableboron crosslinked polymers systems include by non-limiting example, guarand substituted guars crosslinked with boric acid, sodium tetraborate,and encapsulated borates; borate crosslinkers may be used with buffersand pH control agents such as sodium hydroxide, magnesium oxide, sodiumsesquicarbonate, and sodium carbonate, amines (such as hydroxyalkylamines, anilines, pyridines, pyrimidines, quinolines, and pyrrolidines,and carboxylates such as acetates and oxalates) and with delay agentssuch as sorbitol, aldehydes, and sodium gluconate. Suitable zirconiumcrosslinked polymer systems include by non-limiting example, thosecrosslinked by zirconium lactates (for example sodium zirconiumlactate), triethanolamines, 2,2'-iminodiethanol, and with mixtures ofthese ligands, including when adjusted with bicarbonate. Suitabletitanates include by non-limiting example, lactates andtriethanolamines, and mixtures, for example delayed with hydroxyaceticacid. Any other chemical additives may be used or included provided thatthey are tested for compatibility with the viscoelastic surfactant. Forexample, some of the standard crosslinkers or polymers as concentratesusually contain materials such as isopropanol, n-propanol, methanol ordiesel oil.

The viscoelastic surfactant can generally be any viscoelasticsurfactant. The surfactant is present in a low weight percentconcentration. Some suitable concentrations of surfactant are about0.001% to about 1.5% by weight, from about 0.01% to about 0.75% byweight, or even about 0.25%, about 0.5% or about 0.75% by weight.

The VES may be selected from the group consisting of cationic, anionic,zwitterionic, amphoteric, nonionic and combinations thereof. Somenon-limiting examples are those cited in U.S. Pat. Nos. 6,435,277 (Qu etal.) and 6,703,352 (Dahayanake et al.), each of which are incorporatedherein by reference. The viscoelastic surfactants, when used alone or incombination, are capable of forming micelles that form a structure in anaqueous environment that contribute to the increased viscosity of thefluid (also referred to as “viscosifying micelles”). These fluids arenormally prepared by mixing in appropriate amounts of VES suitable toachieve the desired viscosity. The viscosity of VES fluids may beattributed to the three dimensional structure formed by the componentsin the fluids. When the concentration of surfactants in a viscoelasticfluid significantly exceeds a critical concentration, and in most casesin the presence of an electrolyte, surfactant molecules aggregate intospecies such as micelles, which can interact to form a networkexhibiting viscous and elastic behavior.

Non-limiting examples of suitable viscoelastic surfactants useful forviscosifying some fluids include cationic surfactants, anionicsurfactants, zwitterionic surfactants, amphoteric surfactants, nonionicsurfactants, and combinations thereof.

In general, particularly suitable zwitterionic surfactants have theformula:

RCONH—(CH₂)_(a)(CH₂CH₂O)_(m)(CH₂)_(b)—N⁺(CH₃)₂—(CH₂)_(a′)(CH₂CH₂O)_(m′)(CH₂)_(b′)COO⁻

in which R is an alkyl group that contains from about 11 to about 23carbon atoms which may be branched or straight chained and which may besaturated or unsaturated; a, b, a′, and b′ are each from 0 to 10 and mand m′ are each from 0 to 13; a and b are each 1 or 2 if m is not 0 and(a+b) is from 2 to 10 if m is 0; a′ and b′ are each 1 or 2 when m′ isnot 0 and (a′+b′) is from 1 to 5 if m is 0; (m+m′) is from 0 to 14; andCH₂CH₂O may also be OCH₂CH₂.

In an embodiment of the invention, a zwitterionic surfactants of thefamily of betaine is used. Two suitable examples of betaines are BET-0and BET-E. The surfactant in BET-O-30 is shown below; one chemical nameis oleylamidopropyl betaine. It is designated BET-O-30 because asobtained from the supplier (Rhodia, Inc. Cranbury, N.J., U.S.A.) it iscalled Mirataine BET-O-30 because it contains an oleyl acid amide group(including a C₁₇H₃₃ alkene tail group) and contains about 30% activesurfactant; the remainder is substantially water, sodium chloride, andpropylene glycol. An analogous material, BET-E-40, is also availablefrom Rhodia and contains an erucic acid amide group (including a C₂₁H₄₁alkene tail group) and is approximately 40% active ingredient, with theremainder being substantially water, sodium chloride, and isopropanol.VES systems, in particular BET-E-40, optionally contain about 1% of acondensation product of a naphthalene sulfonic acid, for example sodiumpolynaphthalene sulfonate, as a rheology modifier, as described in U.S.Patent Application Publication No. 2003-0134751. The surfactant inBET-E-40 is also shown below; one chemical name is erucylamidopropylbetaine. As-received concentrates of BET-E-40 were used in theexperiments reported below, where they will be referred to as “VES”. BETsurfactants, and other VES's that are suitable for the embodimentsaccording to the invention, are described in U.S. Pat. No. 6,258,859.According to that patent, BET surfactants make viscoelastic gels when inthe presence of certain organic acids, organic acid salts, or inorganicsalts; in that patent, the inorganic salts were present at a weightconcentration up to about 30%. Co-surfactants may be useful in extendingthe brine tolerance, and to increase the gel strength and to reduce theshear sensitivity of the VES-fluid, in particular for BET-O-typesurfactants. An example given in U.S. Pat. No. 6,258,859 is sodiumdodecylbenzene sulfonate (SDBS), also shown below. Other suitableco-surfactants include, for example those having the SDBS-like structurein which x=5-15; other co-surfactants are those in which x=7-15. Stillother suitable co-surfactants for BET-O-30 are certain chelating agentssuch as trisodium hydroxyethylethylenediamine triacetate. The rheologyenhancers of the embodiments according to the invention may be used withviscoelastic surfactant fluid systems that contain such additives asco-surfactants, organic acids, organic acid salts, and/or inorganicsalts.

Some embodiments use betaines; for example BET-E-40. Althoughexperiments have not been performed, it is believed that mixtures ofbetaines, especially BET-E-40, with other surfactants are also suitable.Such mixtures are within the scope of embodiments of the invention.

Other betaines that are suitable include those in which the alkene sidechain (tail group) contains 17-23 carbon atoms (not counting thecarbonyl carbon atom) which may be branched or straight chained andwhich may be saturated or unsaturated, n=2-10, and p=1-5, and mixturesof these compounds. Some betaines are those in which the alkene sidechain contains 17-21 carbon atoms (not counting the carbonyl carbonatom) which may be branched or straight chained and which may besaturated or unsaturated, n=3-5, and p=1-3, and mixtures of thesecompounds. These surfactants are used at a concentration of about 0.5 toabout 10%, or from about 1 to about 5%, or even from about 1.5 to about4.5%.

Exemplary cationic viscoelastic surfactants include the amine salts andquaternary amine salts disclosed in U.S. Pat. Nos. 5,979,557, and6,435,277 which have a common Assignee as the present application andwhich are hereby incorporated by reference. Examples of suitablecationic viscoelastic surfactants include cationic surfactants havingthe structure:

R₁N⁺(R₂)(R₃)(R₄)X⁻

in which R₁ has from about 14 to about 26 carbon atoms and may bebranched or straight chained, aromatic, saturated or unsaturated, andmay contain a carbonyl, an amide, a retroamide, an imide, a urea, or anamine; R₂, R₃, and R₄ are each independently hydrogen or a C₁ to aboutC₆ aliphatic group which may be the same or different, branched orstraight chained, saturated or unsaturated and one or more than one ofwhich may be substituted with a group that renders the R₂, R₃, and R₄group more hydrophilic; the R₂, R₃ and R₄ groups may be incorporatedinto a heterocyclic 5- or 6-member ring structure which includes thenitrogen atom; the R₂, R₃ and R₄ groups may be the same or different;R₁, R₂, R₃ and/or R₄ may contain one or more ethylene oxide and/orpropylene oxide units; and X⁻ is an anion. Mixtures of such compoundsare also suitable. As a further example, R₁ is from about 18 to about 22carbon atoms and may contain a carbonyl, an amide, or an amine, and R₂,R₃, and R₄ are the same as one another and contain from 1 to about 3carbon atoms.

Cationic surfactants having the structure R₁N⁺(R₂)(R₃)(R₄)X⁻ mayoptionally contain amines having the structure R₁N(R₂)(R₃). It is wellknown that commercially available cationic quaternary amine surfactantsoften contain the corresponding amines (in which R₁, R₂, and R₃ in thecationic surfactant and in the amine have the same structure). Asreceived commercially available VES surfactant concentrate formulations,for example cationic VES surfactant formulations, may also optionallycontain one or more members of the group consisting of alcohols,glycols, organic salts, chelating agents, solvents, mutual solvents,organic acids, organic acid salts, inorganic salts, oligomers, polymers,co-polymers, and mixtures of these members. They may also containperformance enhancers, such as viscosity enhancers, for examplepolysulfonates, for example polysulfonic acids, as described in U.S.Pat. No. 7,084,095 which is hereby incorporated by reference.

Another suitable cationic VES is erucyl bis(2-hydroxyethyl) methylammonium chloride, also known as (Z)-13docosenyl-N-N-bis(2-hydroxyethyl) methyl ammonium chloride. It iscommonly obtained from manufacturers as a mixture containing about 60weight percent surfactant in a mixture of isopropanol, ethylene glycol,and water. Other suitable amine salts and quaternary amine salts include(either alone or in combination in accordance with the invention),erucyl trimethyl ammonium chloride; N-methyl-N,N-bis(2-hydroxyethyl)rapeseed ammonium chloride; oleyl methyl bis(hydroxyethyl) ammoniumchloride; erucylamidopropyltrimethylamine chloride, octadecyl methylbis(hydroxyethyl) ammonium bromide; octadecyl tris(hydroxyethyl)ammonium bromide; octadecyl dimethyl hydroxyethyl ammonium bromide;cetyl dimethyl hydroxyethyl ammonium bromide; cetyl methylbis(hydroxyethyl) ammonium salicylate; cetyl methyl bis(hydroxyethyl)ammonium 3,4,-dichlorobenzoate; cetyl tris(hydroxyethyl) ammoniumiodide; cosyl dimethyl hydroxyethyl ammonium bromide; cosyl methylbis(hydroxyethyl) ammonium chloride; cosyl tris(hydroxyethyl) ammoniumbromide; dicosyl dimethyl hydroxyethyl ammonium bromide; dicosyl methylbis(hydroxyethyl) ammonium chloride; dicosyl tris(hydroxyethyl) ammoniumbromide; hexadecyl ethyl bis(hydroxyethyl) ammonium chloride; hexadecylisopropyl bis(hydroxyethyl) ammonium iodide; and cetylamino, N-octadecylpyridinium chloride.

Many fluids made with viscoelastic surfactant systems, for example thosecontaining cationic surfactants having structures similar to that oferucyl bis(2-hydroxyethyl) methyl ammonium chloride, inherently haveshort re-heal times and the rheology enhancers of the embodimentsaccording to the invention may not be needed except under specialcircumstances, for example at very low temperature.

Amphoteric viscoelastic surfactants are also suitable. Exemplaryamphoteric viscoelastic surfactant systems include those described inU.S. Pat. No. 6,703,352, for example amine oxides. Other exemplaryviscoelastic surfactant systems include those described in U.S. Pat.Nos. 6,239,183; 6,506,710; 7,060,661; 7,303,018; and 7,510,009 forexample amidoamine oxides. These references are hereby incorporated intheir entirety. Mixtures of zwitterionic surfactants and amphotericsurfactants are suitable. An example is a mixture of about 13%isopropanol, about 5% 1-butanol, about 15% ethylene glycol monobutylether, about 4% sodium chloride, about 30% water, about 30%cocoamidopropyl betaine, and about 2% cocoamidopropylamine oxide.

The viscoelastic surfactant system may also be based upon any suitableanionic surfactant. In some embodiments, the anionic surfactant is analkyl sarcosinate. The alkyl sarcosinate can generally have any numberof carbon atoms. Alkyl sarcosinates can have about 12 to about 24 carbonatoms. The alkyl sarcosinate can have about 14 to about 18 carbon atoms.Specific examples of the number of carbon atoms include 12, 14, 16, 18,20, 22, and 24 carbon atoms. The anionic surfactant is represented bythe chemical formula:

R₁CON(R₂)CH₂X

wherein R₁ is a hydrophobic chain having about 12 to about 24 carbonatoms, R₂ is hydrogen, methyl, ethyl, propyl, or butyl, and X iscarboxyl or sulfonyl. The hydrophobic chain can be an alkyl group, analkenyl group, an alkylarylalkyl group, or an alkoxyalkyl group.Specific examples of the hydrophobic chain include a tetradecyl group, ahexadecyl group, an octadecentyl group, an octadecyl group, and adocosenoic group.

To provide the ionic strength for the desired micelle formation, in somecases, the treatment fluids of the embodiments according to theinvention may comprise a water-soluble salt. Adding a salt may helppromote micelle formation for the viscosification of the fluid in someinstances. In some embodiments, the aqueous base fluid may contain thewater-soluble salt, for example, where saltwater, a brine, or seawateris used as the aqueous base fluid. Suitable water-soluble salts maycomprise lithium, ammonium, sodium, potassium, cesium, magnesium,calcium, or zinc cations, and chloride, bromide, iodide, formate,nitrate, acetate, cyanate, or thiocyanate anions. Examples of suitablewater-soluble salts that comprise the above-listed anions and cationsinclude, but are not limited to, ammonium chloride, lithium bromide,lithium chloride, lithium formate, lithium nitrate, calcium bromide,calcium chloride, calcium nitrate, calcium formate, sodium bromide,sodium chloride, sodium formate, sodium nitrate, potassium chloride,potassium bromide, potassium nitrate, potassium formate, cesium nitrate,cesium formate, cesium chloride, cesium bromide, magnesium chloride,magnesium bromide, zinc chloride, and zinc bromide.

All thicknened fluids may contain a breaker to reduce fracture formationdamage or to facilitate the return of the fracturing fluids from thefracture as normally used.

The composition also typically contains proppants. The selection of aproppant involves many compromises imposed by economical and practicalconsiderations. Criteria for selecting the proppant type, size, andconcentration is based on the needed dimensionless conductivity, and canbe selected by a skilled artisan. Such proppants can be natural orsynthetic (including but not limited to glass beads, ceramic beads,sand, and bauxite), coated, or contain chemicals; more than one can beused sequentially or in mixtures of different sizes or differentmaterials. The proppant may be resin coated, or pre-cured resin coated,provided that the resin and any other chemicals that might be releasedfrom the coating or come in contact with the other chemicals of theInvention are compatible with them. Proppants and gravels in the same ordifferent wells or treatments can be the same material and/or the samesize as one another and the term “proppant” is intended to includegravel in this discussion. In general the proppant used will have anaverage particle size of from about 0.15 mm to about 2.39 mm (about 8 toabout 100 U.S. mesh), more particularly, but not limited to 0.25 to 0.43mm (40/60 mesh), 0.43 to 0.84 mm (20/40 mesh), 0.84 to 1.19 mm (16/20),0.84 to 1.68 mm (12/20 mesh) and 0.84 to 2.39 mm (8/20 mesh) sizedmaterials. Normally the proppant will be present in the slurry in aconcentration of from about 0.12 to about 0.96 kg/L, or from about 0.12to about 0.72 kg/L, or from about 0.12 to about 0.54 kg/L. The fluid mayalso contain other enhancers or additives.

In other embodiments, the composition may further comprise an additivefor maintaining and/or adjusting pH (e.g., pH buffers, pH adjustingagents, etc.). For example, the additive for maintaining and/oradjusting pH may be included in the treatment fluid so as to maintainthe pH in, or adjust the pH to, a desired range and thereby maintain, orprovide, the necessary ionic strength to form the desired micellarstructures. Examples of suitable additives for maintaining and/oradjusting pH include, but are not limited to, sodium acetate, aceticacid, sodium carbonate, potassium carbonate, sodium bicarbonate,potassium bicarbonate, sodium or potassium diacetate, sodium orpotassium phosphate, sodium or potassium hydrogen phosphate, sodium orpotassium dihydrogen phosphate, sodium hydroxide, potassium hydroxide,lithium hydroxide, combinations thereof, derivatives thereof, and thelike. The additive for adjusting and/or maintaining pH may be present inthe treatment fluids of the embodiments according to the invention in anamount sufficient to maintain and/or adjust the pH of the fluid. One ofordinary skill in the art, with the benefit of this disclosure, willrecognize the appropriate additive for maintaining and/or adjusting pHand amount thereof to use for a chosen application.

In some embodiments, the composition may optionally comprise additionaladditives, including, but not limited to, acids, fluid loss controladditives, gas, corrosion inhibitors, scale inhibitors, catalysts, claycontrol agents, biocides, friction reducers, combinations thereof andthe like. For example, in some embodiments, it may be desired to foamthe composition using a gas, such as air, nitrogen, or carbon dioxide.In one certain embodiment, the composition may contain a particulateadditive, such as a particulate scale inhibitor.

In some embodiments of the invention, the composition may be used forcarrying out a variety of subterranean treatments, where a viscosifiedtreatment fluid may be used, including, but not limited to, drillingoperations, fracturing treatments, and completion operations (e.g.,gravel packing) In some embodiments, the treatment fluids may be used intreating a portion of a subterranean formation. In certain embodiments,the composition may be introduced into a well bore that penetrates thesubterranean formation. Optionally, the treatment fluid further maycomprise particulates and other additives suitable for treating thesubterranean formation. For example, the treatment fluid may be allowedto contact the subterranean formation for a period of time sufficient toreduce the viscosity of the treatment fluid. In some embodiments, thetreatment fluid may be allowed to contact hydrocarbons, formationsfluids, and/or subsequently injected treatment fluids, thereby reducingthe viscosity of the treatment fluid. After a chosen time, the treatmentfluid may be recovered through the well bore.

In certain embodiments, the treatment fluids may be used in fracturingtreatments. In the fracturing embodiments, the composition may beintroduced into a well bore that penetrates a subterranean formation ator above a pressure sufficient to create or enhance one or morefractures in a portion of the subterranean formation. Generally, in thefracturing embodiments, the composition may exhibit viscoelasticbehavior which may be due. Optionally, the treatment fluid further maycomprise particulates and other additives suitable for the fracturingtreatment. After a chosen time, the treatment fluid may be recoveredthrough the well bore.

The composition according to the invention provides the followingbenefits when fracturing permeable formations in the 50 to 90 degCtemperature range, or even the 54 to 82 degC temperature range: higherviscosity at a given temperature with lower polymer concentration (71.1degC at a shear rate of 100 s/s and 25 minutes at temperature—prior artfluid 130 cp, fluid according to the invention 210 cp); improved fluidloss control (static leakoff test in an 80 mD core at71.1 degC—prior artfluid spurt loss 4.81, C_(w)=0.006088, fluid according to the inventionspurt loss 2.61, C_(w)=0.001598); improved shear recovery (viscosity at100/s after 2 minutes shear at 100/s—prior art fluid 100 cp, fluidaccording to the invention 175 cp); less sensitive to the presence ofsurfactants and de-emulsifiers.

The methods of the invention are also suitable for gravel packing, orfor fracturing and gravel packing in one operation (called, for examplefrac and pack, frac-n-pack, frac-pack, StimPac treatments, or othernames), which are also used extensively to stimulate the production ofhydrocarbons, water and other fluids from subterranean formations. Theseoperations involve pumping a slurry of “proppant” (natural or syntheticmaterials that prop open a fracture after it is created) in hydraulicfracturing or “gravel” in gravel packing In low permeability formations,the goal of hydraulic fracturing is generally to form long, high surfacearea fractures that greatly increase the magnitude of the pathway offluid flow from the formation to the wellbore. In high permeabilityformations, the goal of a hydraulic fracturing treatment is typically tocreate a short, wide, highly conductive fracture, in order to bypassnear-wellbore damage done in drilling and/or completion, to ensure goodfluid communication between the rock and the wellbore and also toincrease the surface area available for fluids to flow into thewellbore.

Gravel is also a natural or synthetic material, which may be identicalto, or different from, proppant. Gravel packing is used for “sand”control. Sand is the name given to any particulate material from theformation, such as clays, that could be carried into productionequipment. Gravel packing is a sand-control method used to preventproduction of formation sand, in which, for example a steel screen isplaced in the wellbore and the surrounding annulus is packed withprepared gravel of a specific size designed to prevent the passage offormation sand that could foul subterranean or surface equipment andreduce flows. The primary objective of gravel packing is to stabilizethe formation while causing minimal impairment to well productivity.Sometimes gravel packing is done without a screen. High permeabilityformations are frequently poorly consolidated, so that sand control isneeded; they may also be damaged, so that fracturing is also needed.Therefore, hydraulic fracturing treatments in which short, widefractures are wanted are often combined in a single continuous (“fracand pack”) operation with gravel packing For simplicity, in thefollowing we may refer to any one of hydraulic fracturing, fracturingand gravel packing in one operation (frac and pack), or gravel packing,and mean them all.

In a particular embodiment, fluids that comprise emulsions may beselected. The invert emulsion may be of the reversible type, whereby theinvert emulsion may be converted from a water-in-oil type emulsion to anoil-in-water type emulsion upon exposure to acid, for example. Suchreversible oil-based fluids include those described in U.S. Pat. Nos.6,218,342, 6,806,233 6,790,811, 7,527,097, 7,238,646, 6,989,354,7,178,550, 6,608,006, 7,152,697, 7,178,594, 7,222,672, 7,238,646 and7,3777,721, for example, which are herein incorporated by reference intheir entirety.

In some embodiments, a degradable material such as polylactic orpolyglycolic acid may be used. More information about degradablematerials may be found in U.S. Pat. Nos. 7,380,600, 7,565,929, and7,581,590 which are all three incorporated by reference herein.

Any fracture connecting to the wellbore (either a natural fracture or acreated fracture) may be temporarily sealed during some part of theprocess. Otherwise the open fractures will “steal” fluid from thewellbore and hinder further progress in either drilling or fracturing.Some embodiments relate to ways to chemically seal the fractures,reverse the sealing to make the fractures reconnect to the wellbore, andchemical tracers to verify that the process is occurring as desireddownhole.

Solutions to seal at least temporarily the fractures created are:

-   -   Use swellable proppant: once placed in the fracture the proppant        would swell and decrease the permeability of the proppant pack.        Once the drilling tool is pumped out the hole, a pill could be        used to shrink back the proppant to its original shape. The pill        could dissolve the swellable proppant by pH or by any other        chemical means.    -   Use proppant that would automatically slowly release a chemical        that would shrink the proppant. It could be a slowly dissolvable        material that coat the proppant such as PVA or PVOH. With the        time and temperature the coated layer would dissolve and leave        the core of the proppant intact. The proppant pack conductivity        would be resumed.    -   An alternative is to use a double layer coating made of an        internal oxidizer and an external oxidizable material. With        temperature and time the oxidizer could be triggered to oxidize        the external layer and leave the core of the proppant intact.    -   Another elegant approach would be to use different size of        proppant and use the CRETE concept: weight the proppant stages        with a smaller size particle proppant that is entirely        dissolvable (particles of PVA or particles of oxidizers or        particles of a slowly soluble salt) but which size completely        plugs the fracture faces by invading the pores left by the        bigger size proppant. This would be specifically manageable with        oil based mud where the presence of the oil would decrease        significantly the solubility of the small size particles. When        drilling is complete the particles would dissolve and the        proppant pack conductivity would be resumed.    -   Use swellable proppant: once placed in the fracture the proppant        would swell and decrease the permeability of the proppant pack.        Once the drilling tool is pumped out the hole, a pill could be        used to shrink back the proppant to its original shape. The pill        could dissolve the swellable proppant by pH or by any other        chemical means. Alternatively, unswelling or degradation can be        triggered by dissolution of solid acid in the proppant pack or        wellbore.    -   Use proppant that would automatically slowly release a chemical        that would shrink the proppant. it could be a slowly dissolvable        material that coat the proppant such as PVA or PVOH. With the        time and temperature the coated layer would dissolve and leave        the core of the proppant intact. The proppant pack conductivity        would be resumed.    -   An alternative is to use a double layer coating made of an        internal oxidizer and an external oxidizable material. With        temperature and time the oxidizer could be triggered to oxidize        the external layer and leave the core of the proppant intact.    -   Another elegant approach would be to use different size of        proppant and use a concept based on the CRETE™ system available        from Schlumberger Technology Corporation of Sugar Land, Tex.:        weight the proppant stages with a smaller size particle proppant        that is entirely dissolvable (particles of PVA or particles of        oxidizers or particles of a slowly soluble salt) but which size        completely plugs the fracture faces by invading the pores left        by the bigger size proppant. This would be specifically        manageable with oil based mud where the presence of the oil        would decrease significantly the solubility of the small size        particles. When drilling is complete the particles would        dissolve and the proppant pack conductivity would be resumed.    -   In one approach, CleanSEAL™ technology, which is a technology        platform that may be commercial obtained from Schlumberger        Technology Corporation of Sugar Land, Tex., may be used as a        temporary sealant that is acid degradable. CleanSEAL™ is        comprised of crosslinked HEC, which breaks rapidly on contact        with acid or slowly over time by degradation. A CleanSEAL™        squeeze pill could be placed to seal a fracture entrance at the        wellbore. CleanSEAL™ could be placed in conjunction with solid        acid. Such a squeeze treatment can also temporarily fill natural        fractures connected to the wellbore or created fractures.        Systems can be developed both for breaking with dissolved acid        either by an acid-breaking polymer or by an internal trigger        that is acid-responsive. An effective seal with CleanSEAL™ would        allow us to clean up the wellbore by swabbing and circulating        acid.

Annular protection fluid will have the properties to prevent thestimulation fluid from moving up the wellbore. These properties comefrom the combination of a heavy weight or hydrostatic pressure, highviscosity or yield strength, and or particulates that prevent flow intoa permeable or thief zone. This fluid maybe captured and reused to lowerwaste and cost.

Tracers may be placed in the CleanSEAL™ material so one can chemicallydetect the cleanup process. This detection can even take place downholewith chemical detector instrumentation. Ways to exploit the use of solidacid as it eliminates the need to circulate live acid in a drillingsystem are also desirable.

In some embodiments, fracturing fluid may comprise lubricatingingredients to help remove the drill string.

Methods

FIG. 3 illustrates an embodiment of a drill string assembly 301 in awellbore 302 in a subterranean formation 303. The drill string assembly301 may contain a port or ports 304 that release fluid from the drillstring assembly 301 at high pressure to fracture the formation 303,forming a fracture 305. In some embodiments, the port 304 may release anacid, solid latened slurry or other chemical to notch the formation 303to facilitate fracturing in a later process step as the drill stringmoves through the wellbore or drills the wellbore. In some embodiments,the port 304 may provide a mechanical means such as a slip, dog, or bitto form a notch. In some embodiments, the port 304 may provide aperforating mechanism. In some embodiments, the port 304 may provideproppant to pack the fracture 305. In some embodiments, the port 304 mayprovide viscous material to seal the fracture 305 as described in moredetail below. In some embodiments, the port 304 may be activated bydropping a ball (not pictured in FIG. 3) down the annulus (notpictured).

Initially, the drill string assembly 301 drills the wellbore 302 in thesubterranean formation 303. As it reaches a region that may benefit fromhydraulic fracturing, packers 306 and/or packers 307 may be deployed andfluid is introduced through the ports 304 to form a fracture 305. Thepackers 306 and 307 may be used to protect the wellbore 302 and/or thedrill bit assembly 307 and/or mechanical, chemical, electrical, sonic,or other instrumentation and communication devices housed in the drillstring assembly components 308. The drill string components 308 may alsocollect, administer, and direct the drill string assembly 301 vialogging while drilling information. For example, the components 308 maybe used to identify and direct the drill string assembly 301 to notchregions of the formation 302 that would benefit from fracturing.Additional process steps such as additional fracturing may be desired tofracture regions initially identified with a notch. The components 308may also comprise microseismic measurement capability.

FIG. 3 illustrates an embodiment wherein the fracturing occurs after thedrill string assembly 301, such as downhole drilling equipment, hasformed a wellbore, but alternative embodiments are possible. That is,fracturing could occur ahead of the drilling assembly 308. Further, thisprocess appears to be occurring as the drilling assembly 308 travelsdown the wellbore 302, but the process could also be occurring as thedrilling assembly 308 returns from the depths of the wellbore 302 to thesurface of the wellbore 308 toward the wellhead (not pictured in FIG.3).

In fact, in some embodiments, the advantage of ports 304 is that thefracturing may occur above the drill bit assembly 308, providing highpressure and ease of operation down the annulus 309. That is, it may bedesirable to continue drilling while fracturing. In some embodiments,the packers 306 may be formed of a degradable material selected toprotect or seal the drill bit assembly 307. Alternatively, in someembodiments, a seal may be formed of degradable material that acts aspacker 306 in place of or in addition to seal 306.

In some embodiments, fluid may be pumped through ports such as jets inthe drill bit assembly 307. In some preferred embodiments, fluid may bepumped through ports 304 above the drill bit assembly 307. In someembodiments wherein the packers 307 may or may not be deployed, fluidsmay be pumped through the annulus 309 to produce the fracture 305. Insome embodiments, coiled tubing and the annulus may be used to fractureand drill. In some embodiments, the drilling assembly and annulus may beused to fracture and drill.

In some embodiments, partial return of material may be selected to coolthe bit and to remove tailings. In some embodiments, the fracture maynot be sealed and it may be used for underbalanced drilling, that is,intentionally trying to get flow or not blocking flow may be desirable.

In some embodiments, one approach uses horizontal or highly deviatedwellbore(s). The wellbore(s) is hydraulically fractured several timesalong its length. The fractures are made orthogonal to the wellbore andextend into the reservoir to at least near the boundary edge of thedesired drainage. These long fractures, while very conductive ascompared to the formation, are not conductive enough to meet thedrainage goals of the reservoir. This makes these fractures moreeconomical to create because they use fewer resources. After thefractures are created, additional wellbores or branches from theoriginal well bore are added out further in the formation andintersecting the fractures. These additional wellbores can then drainthe formation through the fractures that were created earlier.

The wellbore itself can be vertical or horizontal or highly deviated upor down and with or without multibraching wellbore(s). The wellbore(s)can be hydraulically fractured several times along its length. Thesefractures are connected directly to the wellbore and extend into thereservoir. This makes these fractures more economical to create as theycan be created as soon as the wellbore is drilled lowering time andassociated cost. One embodiment of the invention provides a means togenerate preferential zones for future fractures as the horizontal wellis drilled.

In some embodiments, thermal stress can be significant in high Young'smodulus formations. Accordingly, embodiments of the invention provide amethod to hydraulically stimulate “tight” high Young's Modulusformations while drilling by significantly cooling the drilling fluid.The method to cool the drilling fluid is to inject liquid CO₂ into thedrilling fluid while drilling in the formation that requires hydraulicstimulation Alternatively, the hydraulic fracture could be induced bysignificantly lowering the temperature of the drilling fluid in the zoneof interest. If the drilling fluid is cooler the than the formationtemperature, the hoop stresses at the well-bore can become tensile andthe injection pressure required to initiate a fracture can be reduced byseveral thousand psi. Such fractures are created while drilling bycooling the drilling fluid which would induce an extra tensile force onthe borehole wall, in proportion to the difference in temperaturebetween borehole fluid and the geological formation.

An additional embodiment creates a self diverting filter cake whiledrilling in a horizontal well, in order to generate fractures in theentire drilled zone at the same time when the zone has been entirelydrilled.

In some embodiments, as drilling is complete, the entire length of thehorizontal well could be fractured, and the zones with the highestpermeability would be preferentially fractured while the zone with thelowest permeability would not accept fracturing fluid. Given that theentire zone should be a pay zone, the exact placement of the mud cakeswith the highest permeability should not be critical.

This process enables economical flow of hydrocarbon fluids or gas inreservoirs that have a combination of the reservoir pressure, fluidproperties and formation permeability result in very low flow to thewellbore(s).

FIG. 4 is a dimensional view of an embodiment of a wellbore 401positioned through several fractures 402 in a reservoir 403 in thesubterranean formation. In a simple block reservoir, this process uses aprimary wellbore 401 that would be horizontal on near horizontal throughthe actual reservoir 403. The wellbore 401 would then be hydraulicallyfractured many times (more than 2 fractures 402) using conventionaltechniques used in the industry to complete the well 404 and isolate thedifferent fractures 402 while they are being made from each other. Thefractures 402 would be left conductive to the reservoir fluids and gasas shown by fluid flow arrows 405 in FIG. 4, but not conductive enoughto satisfactorily drain the reservoir 403 from volumes, time oreconomics.

FIG. 5 is a dimensional view of an embodiment of wellbores 501. Thefractures 502 would then be accessed by another wellbore(s) 501 furtherinto the reservoir 503. This additional wellbore 501 would enable theproduced fluid less restriction to flow by shorting the distance downthe fracture it must travel to a wellbore 501. The wellbore 501 wouldthen open a high capacity venue for the fluid to flow out. Theadditional wellbore(s) 501 may come from another lateral leg from thesame wellbore that is used to make the fractures 502 from or otherwellbores in or near the reservoir 503. The vertical position of theextra wellbores 501 maybe positioned either up or down from the othersto drain a different fluid or gas (as illustrated by the fluid flowlines 504) from the reservoir 503 than the other one(s). An example onebe the lowest wellbore 501 would be water from the fracture and thusfreeing up fracture conductivity for the gas to up and out.

These extra drain holes 501 can be completed without the cost ofisolation completion as it will not be necessary to do so and thislowers cost. If it is desirable to drill the drain hole prior tofracturing, then they can be filled with polymer, drilling fluid, or anymaterial that will help prevent the flow of frac fluid down the wellborewhile fracturing. This process is best used in wells where the rock 505around the wellbore is sufficient strength to produce the well withoutcollapse.

FIG. 6 is a dimensional view of an alternative embodiment of wellbores601 in a subterranean formation 602. That is, the vertical legs of thewellbores 601 may be selected to drain regions of the reservoir 603based upon locations of the fractures 604 and/or flow patterns of thewater, oil, or gas illustrated by the flow lines 605.

FIG. 7 shows a typical sequence of pressure versus time during ahydraulic fracturing operation. The fracture initiation pressure is themaximum pressure shown on the plot above and is determined by the hoopstresses on the formation, the tensile strength of the formation and theformation pore pressure. In low porosity, low permeability or “tight”formations the fracture initiation pressure may be so high that it wouldnot be feasible to attempt fracturing while drilling. By cooling thedrilling fluid so that it is significantly less than the formationtemperature, the fracture initiation pressure could be reducedsignificantly as shown in the following diagram and equations and itwould then be feasible to create a tensile fracture.

The tangential well-bore stress σ_(θθ) as illustrated in someembodiments by FIG. 10 is given by;

σ_(θθ)=σ_(H)+σ_(h)−2(σ_(H)−σ_(h))cos 2θ−2P _(o)−(P _(b) −P _(o))  (1)

where σ_(H) is the maximum horizontal stress,σ_(h) is the minimum horizontal stress,θ is the angle relative to maximum horizontal stressP_(o) is the formation pore pressureP_(b) is the borehole hydraulic pressure

In the case where θ=0 or 180 which is where the tensile forces will begreatest and in formations where permeability is very low and we canneglect the formation pore pressure equation (1) reduces to

σ_(θθ)=3σ_(h)−σ_(H) −P _(b)  (2)

If the borehole fluid temperature is less than the formation temperaturethere will be an extra tensile force

σ_(T) =−αEΔT/1−γ  (3)

where σ_(T) is the thermal stressα is the linear coefficient of thermal expansion of the formationE is the Young's Modulus of the formationΔT is the temperature difference between borehole fluid and formationγ is the Poisson's ratio of the formationIncluding equation 3 in equation 2 we now have

σ_(θθ)=3σ_(h)−σ_(H)+σ_(T) −P _(b)  (4)

Where σ_(T) is a negative or tensile force if the drilling fluid iscooler than the formation.

If the sum of all the terms on the right hand side of equation 4 arenegative (tensile) and exceed the tensile strength of the formation, afracture will initiate. The tensile strength of most rock formations isassumed to be 1/12 of the compressive strength. For example, in aformation with a compressive strength of 24000 psi we'd expect a tensilestrength of 2000 psi. If the minimum horizontal stress were 5000 psi andthe maximum horizontal stress were 6000 psi, and the hydraulic pressurefrom the drilling fluid were 4000 psi, a fracture could be initiated ifthe thermal stress exceeded 3000 psi. For formations with high Young'sModulus, the tensile forces due to thermal stress are of the order of1000 psi for every 10 degrees Celsius the drilling fluid is cooler thanthe formation temperature. Thus if the mud could be cooled to 30 degreesCelsius cooler than formation temperature, a tensile fracture would beinitiated.

The thermal stress is highest in zones of high Young's Modulus, andtight, low porosity zones which are difficult to conventionallyhydraulically stimulate can have Young's moduli sufficiently high thatthe thermal stress would facilitate creating a tensile fracture. Thiscould be achieved by significantly increasing the mud weight or the pumppressure while drilling through the interval requiring hydraulicfracturing.

In some embodiments, a packer may be placed above the drill bit.Judicial placement of a packer above the drill bit would improve theefficiency further. By cooling the borehole fluid sufficiently, atensile fracture could be initiated without exceeding the pressurerating of the packer. In some embodiments, a packer may be activatedwhen the drilling fluid is cooled sufficiently and/or before fracturingoccurs.

An alternative therefore to fracturing while drilling is to drill theentire well and generate fractures from different zones at the end ofthe drilling operation all in once at the same time. The drilling andfracturing fluids can be different and the drilling equipment can be atleast partially removed (in case of an horizontal well) and not damagedby the proppant stages. This implies, however, the use of a diversiontechnique in order to fracture all the zones at once.

An additional embodiment of a fracturing while drilling process is alsoprovided. The process depends on the idea of drilling some distance into the reservoir, fracturing a zone, temporarily sealing a zone, thenresuming drilling. The process repeats until the desired length of thewellbore has been drilled and fractured.

The process, as illustrated in some embodiments by FIG. 8 and in someembodiments by FIG. 9, is as follows.

1) Once drilled through or partially through zone of interest orreservoir 801, circulate annular protection fluid to the annulus.

2) prop ball 802 and displace with cutting or formation breakdown fluid.

3) Open cutting ports (not shown) and cut or break down formation 805 toinitiate the fracture 804.

4) propand displace larger ball 803 to open frac ports (not shown).

5) Fracture well.

6) Pull pipe 806 up to shear the annular protection fluid 807 andcirculate or reverse out of the wellbore 808. Reverse balls 803, 802 tosurface at this time.

7) Run drilling pipe 806 back to bottom to close ports.

8) Continue drilling to next interval 809.

9) Repeat steps 1 through 8 until all zones are stimulated. (FIG. 6)

10) Come out of the wellbore with the drilling assembly 810. Flow wellto produce

In the above process, the drilling assembly maybe pulled back up thehole for up to 1000′ to insure the security of the assembly in case ofwellbore collapse.

In an alternative embodiment, one could place an additive such as alatex or an emulsion that would replace temporarily the mud cake or thatwould be placed on the top of the mud cake and decrease locally thepermeability of the mud cake. This additive would be placed in stageseither of various concentrations or in an on and off manner. When theadditive is present the mud cake would be of very low permeability sincethe additive would form an impermeable film of the surface of the mudcake, when the additive is not present the mud cake would be of standardpermeability value encountered with standard mud cakes.

When the entire zone is drilled, the drilling equipment would be removedleaving a drilling well with zones of lowest permeability than others.As fracturing fluid would be pumped in the horizontal well at a pressuresufficient to crack the rock wherever the permeability is high enoughdifferent zones would be fractured. The zones of lowest permeabilitywould not allow fluid entry and would not be fractured.

An alternative embodiment may place in the additive a responsivematerial such as a material that is electro-sensitive ormagneto-sensitive. As the drilling equipment is removed from thehorizontal well from the tip of the well to the wellbore, a signal wouldbe sent through the drilling bit on the way out that would activate theadditive wherever it is placed and for example degrade the mud cake forpreferential fluid entry. The sequence described above would be invertedbut the principle remains the same.

-   -   As the well is drilled place in various amounts (or on/off        sequence) an additive in the drilling mud that would be placed        inside the mud cake whenever present.    -   When the entire zone is drilled, the drilling bit on the way        back would activate the additive by sending electric pulses        (range of action short enough to be able to activate the        additive) or pressure pulses. Wherever the additive is present        the mud cake would be removed.    -   Wherever the mud cake has been removed, the local permeability        would be much higher enabling preferential entry of the        fracturing fluids, ie. The additives would be diverting the        fracturing fluid in the entire drilled well.

The responsive material could be a drilling mud cake breakerencapsulated in a pressure sensitive membrane or encapsulated inmagnetic material that would revert or change conformation with a localmagnetic field.

An important note is that the material does not have to invade theentire fracture but it could be used in the first few inches of thefracture length as long as the seal is strong enough to not be openagain while the next fractures are open.

Another note is that the described inventions here could be used inother (and maybe more relevant) applications than fracturing whiledrilling such as means of diverting agents, or sand control issues.

An important note is that the material does not have to invade theentire fracture but it could be used in the first few inches of thefracture length as long as the seal is strong enough to not be openagain while the next fractures are open.

In some embodiments, bypassed zones may be the target for combineddrilling and fracturing. Instead of “starting over” with a new well fromthe surface, one option is to drill off horizontally from existingwells. This can be done either with coiled tubing drilling or withrotary steerable technology. Ideally, this horizontal section will befractured in numerous places to maximize connectivity of the reservoirto the wellbore.

The above processes can be also used to stimulate the formation whereacid or other chemical that will dissolve the rock, such as HCl withCarbonate formation, to stimulate will be injected below fracturingpressures. This etches the face of an already present fracture orwormhole a small channel some distance from the wellbore out into theformation.

Advantages

A technique that requires less fracturing operations and less hardwarefor completion in the wellbores will reduce cost of field developmentand speed up production. This will reduce cost of field development andspeed up production.

This process enables economical flow of hydrocarbon fluids or gas inreservoirs that have a combination of the reservoir pressure, fluidproperties and formation permeability result in very low flow to thewellbore(s).

The methods herein could be used in other applications than fracturingwhile drilling such as means of diverting agents, or resolving sandcontrol issues.

In formations where an open hole completion is desired, such ashorizontal wells in tight formations, fracturing while drilling wouldlead to significant savings in rig time and operational efficiency.

The preceding description has been presented with reference to presentlypreferred embodiments of the invention. Persons skilled in the art andtechnology to which this invention pertains will appreciate thatalterations and changes in the described structures and methods ofoperation can be practiced without meaningfully departing from theprinciple, and scope of this invention. Accordingly, the foregoingdescription should not be read as pertaining only to the precisestructures described and shown in the accompanying drawings, but rathershould be read as consistent with and as support for the followingclaims, which are to have their fullest and fairest scope.

1. A method for processing a subterranean formation, comprising:stimulating and fracturing a subterranean formation; and drilling thesubterranean formation, wherein the drilling and fracturing occurswithout removing downhole drilling equipment from the formation.
 2. Themethod of claim 1, wherein the drilling and fracturing form a conductivefracture using acid.
 3. The method of claim 1, further comprisingforming a seal along a surface of the formation.
 4. The method of claim3, wherein the seal is temporary.
 5. The method of claim 3, wherein theseal is placed during drilling.
 6. The method of claim 1, wherein thedrilling occurs using a fluid selected for its density and its abilityto modify fluid temperature.
 7. The method of claim 1, furthercomprising introducing a composition along the surface of thesubterranean formation.
 8. The method of claim 7, wherein thecomposition stabilizes the surface of the subterranean formation.
 9. Themethod of claim 7, wherein the composition has a stability that istailored to degrade over time.
 10. The method of claim 7, wherein thecomposition comprises carbon dioxide or nitrogen.
 11. The method ofclaim 7, wherein the composition is electrosensitive or magnetosensitive.
 12. The method of claim 7, wherein the composition comprisesa material that melts below formation temperature.
 13. The method ofclaim 7, wherein the composition comprises crosslinked polymers.
 14. Themethod of claim 1, wherein the fracturing comprises proppant.
 15. Themethod of claim 14, wherein the proppant comprises material to make itswell, shrink, or form acid.
 16. The method of claim 14, wherein theproppant comprises proppant with multiple diameters.
 17. The method ofclaim 1, wherein a filter cake is formed along a surface of thesubterranean formation.
 18. The method of claim 17, wherein the filtercake comprises a breaker material.
 19. The method of claim 18, whereinthe material is encapsulated.
 20. The method of claim 17, wherein thefilter cake comprises a material to decrease cake permeability.
 21. Themethod of claim 17, wherein the material comprises latex or an emulsion.22. The method of claim 17, wherein the filter cake is tailored toprevent or allow fracture.
 23. The method of claim 17, wherein thefilter cake is self-diverting.
 24. The method of claim 1, wherein theequipment comprises a drill string.
 25. The method of claim 1, furthercomprising controlling and/or blocking the fluid return system.
 26. Themethod of claim 1, wherein a pressure on the outer surface of a drillbit is controlled.
 27. The method of claim 1, further comprising pumpingfluid through a bypass, annulus, or a drill string.
 28. The method ofclaim 1, further comprising collecting cuttings via a drillstring orannulus.
 29. The method of claim 1, further comprising introducing apacker into the wellbore.
 30. The method of claim 1, further comprisingtriggering the fracturing by dropping a ball into the drillstring. 31.The method of claim 1, further comprising using optical fibers toprovide feedback to control the fracturing.
 32. The method of claim 1,wherein the drilling occurs horizontally, vertically, and/or withmultiple branches.
 33. The method of claim 1, further comprisingmeasuring microseismic, temperature, sonic, information and controllingthe fracturing and/or drilling using the information.
 34. The method ofclaim 1, wherein the fracturing comprises introducing a foam or anenergized fluid into the wellbore.
 35. The method of claim 1, whereinthe fracturing occurs as a drill string assembly is traveling away froma wellhead.
 36. The method of claim 1, wherein the fracturing occurs asa drill string assembly is traveling toward a wellhead.
 37. An apparatusfor drilling and fracturing a subterranean formation, comprising: adrill string assembly; and a hydraulic fracturing system, wherein thedrill string and fracturing system are in communication with a wellboreand wherein the drill string and a fracture formed by the hydraulicfracturing system are less than about 1000 feet apart.
 38. The apparatusof claim 37, further comprising a packer.
 39. The apparatus of claim 37,wherein the drill string is configured to withstand exposure tohydraulic fracturing.
 40. The apparatus of claim 37, wherein thehydraulic fracturing system is configured to fracture one stage at atime.
 41. The apparatus of claim 37, further comprising a seal thatencompasses a wellbore, drill string, and a hydraulic fracturing fluidinlet port.
 42. The apparatus of claim 37, wherein the drill string isconfigured to deliver hydraulic fracturing fluid.
 43. A method forprocessing a subterranean formation, comprising: fracturing asubterranean formation using a hydraulic fracturing system; and drillingthe subterranean formation using a drill string assembly, wherein thedrilling and fracturing occurs without removing the drill string fromthe formation, and wherein the fracturing occurs via ports in the drillstring assembly.